|Publication number||US6910535 B2|
|Application number||US 10/298,251|
|Publication date||Jun 28, 2005|
|Filing date||Nov 15, 2002|
|Priority date||Nov 15, 2002|
|Also published as||CA2505896A1, CA2505896C, EP1563163A1, US6994164, US20040094298, US20050039920, US20050080161, WO2004046501A1|
|Publication number||10298251, 298251, US 6910535 B2, US 6910535B2, US-B2-6910535, US6910535 B2, US6910535B2|
|Inventors||Uday A. Tare, James F. Heathman, Krishna M. Ravi|
|Original Assignee||Halliburton Energy Services, Inc.|
|Export Citation||BiBTeX, EndNote, RefMan|
|Patent Citations (20), Non-Patent Citations (5), Referenced by (3), Classifications (7), Legal Events (4)|
|External Links: USPTO, USPTO Assignment, Espacenet|
The current invention relates to a method for enhancing formation stability during well construction. The method of the current invention improves the process of formulating cementing fluids (flushes, spacers, and cement slurries) such that the fluids reduce the risk of formation instability during well completion operations. More specifically, the current invention relates to a test for determining the optimum cementing fluid formulation for use in water sensitive, reactive formations.
Water sensitive, reactive formations include but are not limited to marl, clay bearing sandstone, clay bearing carbonates, shale stringers in salt formations and carbonate formations. Shales are among the most commonly encountered formations. Shales are fine-grained sedimentary rocks composed of clay, silt and in some cases fine sands. For the purpose of this discussion, shale will be termed as a loosely defined heterogeneous argillaceous material ranging from clay-rich gumbo (relatively weak) to shaly siltstone (highly cemented), with the common characteristic of having an extremely low permeability and contains clay minerals. Argillaceous formations like shales make up over 75 percent of drilled formations and cause over 90 percent of wellbore instability problems. Instability in shales is a continuing problem that results in substantial annual expenditure by the petroleum industry—in excess of a billion dollars according to conservative estimates.
A drilling fluid system (drilling mud) is an essential part of a conventional drilling process and consists of different solid and fluid components. When interacting with subterranean formation material such as shale and other water-sensitive, reactive formations, cementing fluids exhibit many of the same physical and chemical functionalities and properties as drilling mud. Different performance enhancing components may be added to any of these fluids. As known to those skilled in the art, the primary functions of a drilling fluid include the removal of rock material during drilling, imparting hydraulic support to the borehole to help ensure stability, providing lubrication to reduce friction between the borehole surface and drill pipe, cooling the drill bit, etc. Cementing preflushes and spacers serve the function of removing the drilling fluid in preparation for the cement slurry, as well as separating potentially incompatible drilling fluids from cement slurries. Finally, the cement will serve the ultimate function of zonal isolation and structural support. In each instance, the properties of these fluids are adjusted to account for the changing characteristics of wellbore formations encountered.
Cementing fluids often include several different salts (e.g. NaCl, KCl, and CaCl2) for various purposes such as intentionally affecting (shortening) slurry set times, cementing across salt formations, and supposed protection of productive formations that may contain water-sensitive clays. Historically, salt content in cement slurries has varied from one or two percent to saturation with NaCl. Use of KCl and CaCl2 is usually limited to no more than three or four percent. Further, seawater or brine is frequently added at the wellbore location to the cement composition as makeup water to produce a cement slurry having a suitable density and pumpability.
However, the use of salts in cement slurries has not been consistent with respect to formation issues. The position is frequently taken that the high pH of cement slurry, along with its minimal amount of calcium in solution, will suffice to provide formation protection in most cases. However, very little actual supporting evidence for this assumption has been found. Further, most testing reported in the literature has been based on regained permeability testing of sandstone cores. Although very meaningful to the understanding of that specific issue, any connection between effects on clays in permeable sandstones and formation instability as related to shales is complicated by precipitation of various calcium salt species from cement slurries. The pros and cons of this issue are frequently debated with no clear outcome. When salts are applied, presumably for formation stability purposes, it is frequently done without a true understanding of the method or outcome. Additionally, use of salts specifically in cementing spacers and preflushes is seldom applied.
In addition to salts, there are many other additives in cementing fluids. Polymers of many types (e.g. blends containing HEC, CMHEC, and various synthetic polymers) as well as silicates are a frequent component in cement slurries. They serve several functions including prevention of slurry dehydration and annular bridging during placement, enhanced bonding across permeable zones, rheology adjustment, and as an aid to gas migration control. However, combining salts and fluid loss additives in the same slurry frequently presents a more complicated and costly scenario because many fluid loss additives do not hydrate and/or otherwise function as efficiently in the presence of high concentrations of soluble salts. This cost-driven approach to achieving cement slurry fluid loss values has resulted in the reduction and general elimination of salts in most primary cementing slurries without a true understanding of the resulting effects on wellbore stability.
Thus, a need exists for a method of accurately formulating cementing fluids which will enhance formation stability.
The current invention provides a method for enhancing subterranean formation stability. In particular, the current invention is directed to a method for enhancing the stability of water-sensitive, reactive subterranean formations. According to the method of the current invention, a sample of the targeted subterranean formation or a similar subterranean formation is obtained and placed in a testing device. The sample is placed under a confining pressure approximately equal to the pressure encountered in the subterranean formation. The confining pressure will be maintained on the sample for the duration of the test procedure. Additionally, back-pressure is applied on the upstream side of the sample by a fluid similar to the fluid present in the pores of the subterranean formation. Subsequently, the back-pressure is released and the sample allowed to consolidate. Following consolidation, upstream pressure is applied to the sample while monitoring the downstream pressure exerted by the shale sample. Once the downstream pressure has increased by at least 50 percent, the upstream pressure is removed. The downstream and upstream pressures are monitored and allowed to equilibrate or at least stabilize. Thereafter, upstream pressure is again applied to the sample by pumping a cementing fluid through the testing device. As the cementing fluid contacts and applies pressure to the sample, the change in downstream pressure is measured. The water activity of the cementing fluid is adjusted in response to the change in downstream pressure to provide an economical cementing fluid formulation having a positive stability enhancing impact on the subterranean formation.
The current invention also provides a method for formulating cementing fluids to be used in a wellbore penetrating a water-sensitive, reactive subterranean formation. The method of the current invention provides cementing fluids formulated to reduce or eliminate the likelihood of formation instability during the cementing process. According to the method of the current invention, a sample of the targeted subterranean formation or formation of similar composition is obtained and placed under a confining pressure in a suitable testing device. Using a fluid similar to formation pore fluid (simulated pore fluid), back-pressure approximating the in situ pore pressure of the formation is applied to the sample. Thereafter, removing the back-pressure while maintaining the confining pressure consolidates the sample. Subsequently, upstream pressure is applied to the sample using the simulated pore fluid while monitoring the downstream pressure. Once the downstream pressure has increased by at least 50 percent, the upstream pressure is removed and the upstream and downstream pressures are allowed to approximately equilibrate. Following stabilization of the upstream and downstream pressures, upstream pressure is once again applied to the sample using a cementing fluid. During the application of upstream pressure, the change in downstream pressure is measured. In response to the change in downstream pressure, the water activity of the cementing fluid may be increased or decreased. The process steps of applying upstream pressure, measuring the change in downstream pressure and adjusting the water activity of the cementing fluid are repeated until the downstream pressure is less than or equal to the upstream pressure. Preferably, the downstream pressure is less than the upstream pressure.
Additionally, the current invention provides a method for enhancing the stability of a water sensitive, reactive formation penetrated by a wellbore during the cementing process. The method of the current invention comprises formulating cementing fluids having low water activity levels and capable of applying an osmotic semi-permeable membrane on the face of the formation. According to the method of the current invention, a sample of the targeted subterranean formation or formation of similar composition is obtained and placed under a confining pressure in a suitable testing device. Using a fluid similar to formation pore fluid (simulated pore fluid), back-pressure approximating the in situ pore pressure of the formation is applied to the sample. Thereafter, removing the back-pressure while maintaining the confining pressure consolidates the sample. Subsequently, upstream pressure is applied to the sample using the simulated pore fluid while monitoring the downstream pressure. Once the downstream pressure has increased by at least 50 percent, the upstream pressure is removed and the upstream and downstream pressures are allowed to approximately equilibrate. Following stabilization of the upstream and downstream pressures, upstream pressure is once again applied to the sample using a cementing fluid. During the application of upstream pressure, the change in downstream pressure is measured. In response to the change in downstream pressure, the water activity of the cementing fluid may be increased or decreased. Additionally, prior to or during the cementing operation, an osmotic semi-permeable membrane is applied to the face of the subterranean water sensitive, reactive formation.
The current invention relates to methods for enhancing the stability of water-sensitive, reactive formations such as shale formations and to methods for accurately formulating cementing fluids. Those skilled in the art are familiar with the benefits of incorporating various salts and other compounds into the formulations of cementing fluids to limit the detrimental effects of such fluids on formation stability. However, prior to the current invention, the process of formulating the cementing fluids was one of “trial and error.” The current invention provides an accurate method for simulating the downhole environment of the subterranean formation including the impact of cementing fluids on the subterranean formation. By assessing the impact of cementing fluids on the subterranean formation, the current invention provides methods for enhancing formation stability and improved methods for formulating cementing fluids.
One critical aspect of maintaining formation stability is the balancing of fluid pressure within the pores of the formation, known as pore pressure, by the fluid pressure within the borehole, known as borehole pressure. Thus, the transport of water between the borehole and the formation directly impacts the stability of the formation. In general, the two most relevant mechanisms for water transport in and out of shale and other water sensitive formations are: (1) the hydraulic pressure difference between the wellbore pressure (equivalent total fluid column density) and the formation pore pressure; and, (2) the chemical potential difference, i.e., water activity, between the wellbore fluid and the pore fluid within the formation. Accordingly, it is desirable to control the flow of water from the wellbore into and out of the formation in order to maintain formation stability.
As will be discussed herein, the current invention utilizes two primary methods for controlling the flow of water into and out of the formation. First, the current invention provides a method for formulating cementing fluids preferably having a water activity lower than the water activity of the pore fluid within the formation. Second, the current invention additionally provides for the generation of an osmotic, semi-permeable membrane on the face of the formation.
If the cementing fluids have a higher water activity level than the pore fluid within the formation, then water will flow from the wellbore into the pores of the formation. As water enters the formation pores, formation pore pressure increases ultimately leading to formation instability. However, if cementing fluids are formulated with a water activity level less than the water activity level of the pore fluids, then water will flow outwards from the formation into the wellbore. The outward flow of water from the formation effectively increases the fluid pressure within the wellbore thereby further stabilizing the formation. Thus, knowledge of the chemical potential of the cementing fluids, i.e., water activity, and the impact of that potential on the formation permits the formulation of cementing fluids that will enhance wellbore stability.
As noted above, one aspect of the current invention is a method of formulating cementing fluids capable of enhancing the stability of water sensitive, reactive formations. The method of formulating the cementing fluids utilizes a testing device such as depicted in
The method of formulating cementing fluids will be described with reference to the testing device 20 of FIG. 1. Referring to
Device 20 of
For the purposes of the following description of the cementing fluid testing procedure, the term “downstream pressure” corresponds to the pore pressure exerted by the targeted formation. The term “confining pressure” refers to the in situ pressure applied to the overall formation. The term “upstream pressure” corresponds to the hydrostatic pressure exerted by fluids within the borehole. The term “back pressure” corresponds to the pore pressure of the formation as applied to the face of sample 10 during back-pressure saturation. Back-pressure saturation is a step carried out to restore formation pore pressure and ensure complete saturation of sample 10 with the simulated pore fluid. The following test procedure is used to evaluate the impact of cementing fluids on the pore pressure of the formation:
As will be demonstrated by way of the following examples, use of the foregoing method enables the formulation of cementing fluids suitable for enhancing the stability of the subterranean formation. Specifically, the foregoing method provides an accurate simulation of the downhole environment. Thus, the change in downstream pressure duting testing of the cementing fluid in device 20 reflects the relative differences in water activity levels between the cementing fluid and the pore fluid. Accordingly, analysis of the test results will indicate whether or not the cementing fluid has a water activity level sufficiently low enough to enhance formation stability. If the downstream pressure is greater than the upstream pressure, then the water activity level of the cementing fluid must belowered. Because this method reflects the downhole conditions of the wellbore, the water activity of the cementing fluid can be continually adjusted and re-tested until the desired activity is reached or no further adjustment is possible.
Adjustment of the water activity level of the cementing fluid is carried out by adding salts and other compounds to the cementing fluid. Preferred compounds for adjusting the water activity level of the cementing fluids include but are not limited to water-soluble salts of calcium, sodium, potassium, magnesium and the like, and glycols and like derivatives such as ethylene glycol, propylene glycol, and other compounds as known by those skilled in the art as being capable of reducing water activity levels.
If the water activity level of the cementing fluid can not be lowered further, then additional steps to protect the formation must be taken as described below. However, in many instances merely slowing the increase in pore pressure will suffice, as the cementing process will frequently be completed, including setting of the cement, prior to a detrimental increase in pore pressure.
If testing of the cementing fluid indicates that the pore pressure cannot be lowered or if the increase in pore pressure is not sufficiently retarded to protect the stability of the subterranean formation, then additional steps must be taken to preserve the integrity of the formation. One means available for further enhancing the stability of the formation is the generation of an osmotic membrane on the face of the formation penetrated by the wellbore. The methods of generating such membranes and the effectiveness of such membranes are known to those skilled in the art as demonstrated by the paper entitled “Development of Novel Membrane Efficient Water-Based Drilling Fluids Through Fundamental Understanding of Osmotic Membrane Generation in Shales,” by Fersheed K. Mody, Uday A. Tare, Chee P. Tan, Calum J. Drummond, and Bailin Wu, presented at the SPE Annual Technical Conference and Exhibition held in San Antonio, Tex., October 2002 and by published PCT Application No. WO 02/053873, published on Jul. 11, 2002 and assigned to the assignee of this invention. Both references are incorporated herein by reference.
Thus, the generation of an efficient semi-permeable membrane will help ensure adequate outflow of water from the formation or at least minimize the flow of water into the formation due to wellbore pressure. Incorporating additives known to those skilled in the art into the cementing fluid formulation can increase the efficiency of the semi-permeable membrane. For example, the following non-limiting list of additives if applied correctly may increase the efficiency of a semi-permeable membrane formed on the face of a shale formation: electrolytes, phenols, tetra methylammonium laurate, tetra methylammonium oleate, silicic acid, potassium methyl siliconate, sodium methyl siliciconate, biopolymers, hydroxyethyl cellulose, sodium carboxylmethyl-hydroxethyl cellulose, synthetics such as polyethylene amines, copolymers of 2-acrylamide-2-methyl propane sulfonic acid and N-vinyl-N-methyl acetamide, HALAD-344 (a random copolymer of 2-acrylamide-2-propane sulfonic acid and N,N-dimethyl acrylamide), HALAD-413 (a caustized lignite grafted with 2-acryamide-2-methylsulfonic acid, N,N-dimethylacrylamide, and acrylamide), latexes such as polyvinylalochol and styrene butadiene, and silicate compounds such as sodium silicate and potassium silicate.
The following examples are provided merely to enhance the understanding of the current invention and are not considered limiting with regard to the scope of the invention. Example 1 demonstrates how variations in concentration influence pore pressure. Examples 2-6 demonstrate the use of the testing method described above as a means for evaluating the impact of a compound on pore pressure. The following fluids were tested according to the foregoing method:
Fluid A—a cement filtrate produced by mixing API Class H Portland cement with approximately 38% fresh water and extracting said filtrate from said slurry in accordance with API Recommended Practice 10B, 22nd edition, December 1997.
With reference to
For Examples 2-5,
The initial increase in downstream pressure reflects the performance of the Back-pressure Saturation step. The drop in pressure represents the subsequent Consolidation step. Thereafter, changes in downstream pressure are influenced by the application of upstream pressure to the shale sample. On about day 2 of each test, upstream pressure (Pore Fluid Pressure Transmission) is applied to the sample. This increase in upstream pressure reflects the expected pressure to be applied by the cementing fluid in the downhole environment. This pressure is removed and the sample allowed to re-consolidate as reflected by the drop in pressured depicted by both lines B and C. Following reconsolidation, the sample is ready for testing by applying pressure with a cementing fluid.
The upstream pressure applied with the cementing fluid reflects the expected borehole pressure during a cementing operation. If the downstream pressure corresponds to the upstream pressure, as in
As used in the examples 2-5, the term KCl reflects the addition of sufficient KCl to the cementing fluid to yield a 5% KCl solution based on the weight of the water used to make up the cementing fluid.
Example 2, as shown in
Example 3, as shown in
Example 4, depicted by
Example 5, as shown in
Thus, the current invention provides a valuable testing method for determining the impact of cementing fluids on water sensitive, reactive formations. The current invention further provides the ability to formulate cementing fluids which will enhance the stability of such formations. Additionally, the current invention provides methods for enhancing formation stability of water sensitive, reactive formation penetrated by a wellbore during cementing operations.
While the present invention has been described in detail with reference to
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|U.S. Classification||166/250.14, 166/292, 73/152.07, 166/293|
|Jun 11, 2003||AS||Assignment|
Owner name: HILLIBURTON ENERGY SERVICES, INC., TEXAS
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:TARE, UDAY A.;HEATHMAN, JAMES F.;RAVI, KRISHNA M.;REEL/FRAME:014165/0269;SIGNING DATES FROM 20030505 TO 20030528
|Sep 27, 2005||CC||Certificate of correction|
|Sep 18, 2008||FPAY||Fee payment|
Year of fee payment: 4
|Oct 4, 2012||FPAY||Fee payment|
Year of fee payment: 8